A significant fraction of the oil-in-place is left in the ground after primary or secondary recovery. Gas injection, sometimes referred to as gas flooding, has been used to recover this remaining oil. The terms "gas injection" and "gas flooding" as used herein will mean an oil recovery process in which the fluid injected is a hydrocarbon gas, inert gas, carbon dioxide or steam.
The success of gas floods has been diminished by the unfavorable mobility and density ratios between the gas and reservoir fluids. The viscosities of gases are often 10 to 100 times less than oil and water viscosities. At these unfavorable ratios, gases finger and channel through the formation, leaving parts of the reservoir unswept. Added to this fingering is the inherent tendency of a highly mobile gas to flow preferentially through the more permeable rock sections or to gravity override in the reservoir. These basic factors--permeability variations and unfavorable mobility and density ratios--greatly reduce the effectiveness of gas floods and may make them uneconomic. One apparent remedy is to control the mobility of the injected gas.
It has been suggested that the mobility of the gas may be reduced by injecting into a formation or forming in situ a mixture of a gas and an aqueous surfactant solution. Such mixtures are commonly referred to as foams. Since the effective viscosity of foam is greater than the viscosities of its components, it has been suggested that such mixtures of gas and aqueous surfactant solution will help improve the sweep efficiency of gas drives.
Foam is a dispersion of a large volume of gas in a relatively small volume of liquid. It should be noted, however, that at reservoir conditions several gases, including CO.sub.2, exist as a dense fluid, resembling a liquid more than a gas. For this reason, the term "solvent" is sometimes used to describe the "gas" and the term "emulsion" is sometimes used to describe the solvent-water mixture.
The choice of surfactant for use as a mobility control agent is crucial. Ideally, the surfactant should reduce gas mobility enough to adequately improve sweep efficiency, but not so much as to impair gas injectivity and thus significantly delay oil recovery. Furthermore, surfactant retention should be as low as possible to help minimize the amount of surfactant required.
The method used to inject the surfactant solution and gas is also crucial. The surfactant solution should be delivered to regions of the reservoir where it is needed and in such a way that the necessary interaction with the gas occurs to reduce gas mobility. Injection of excessive amounts of surfactant, or injection of surfactant into regions of the reservoir where gas mobility reduction is not desired will have an adverse impact on the economic feasibility of the process.
There is substantial uncertainty about the most effective method for implementing a foam mobility control process. Numerous procedures for injecting water-soluble gas mobility control agents have been proposed, but there is little consensus about the most effective injection procedure.
U.S. Pat. No. 2,866,507 describes a foam flooding process in which an aqueous solution of the foaming agent is introduced into the formation immediately prior to gas injection.
U.S. Pat. No. 3,185,634 describes a foam flooding process in which a stable foam is pregenerated prior to injection into the formation.
U.S. Pat. No. 3,318,379 discloses a foam drive process in which injection of surfactant is followed by injection of a nongaseous, surfactant-free liquid, which is followed in turn by injection of gas to form a foam. The nongaseous fluid, which may be water, is injected to displace surfactant away from the vicinity of the well and prevent loss of injectivity caused by foam formation near the well. These steps may be repeated.
U.S. Pat. No. 3,491,832 discloses a foam plugging process in which small alternate batches of surfactant solution and gas are injected. A batch of spacer liquid, such as water, may be used between the surfactant and gas to avoid excessive plugging of the formation near the well.
U.S. Pat. No. 3,653,440 discloses a method for reducing the mobility of an aqueous surfactant solution. This surfactant flooding process consists of injection of a slug of "active" surfactant, followed by alternate slugs of gas and an aqueous drive liquid. The "active" surfactant is capable of reducing oil/water interfacial tension to less than 0.01 dyne/cm, and thus is the primary oil displacement fluid. The aqueous drive liquid preferably contains a lower, inactive, concentration of surfactant. The gas and aqueous drive liquid are injected in rates and amounts that cause the gas to move ahead of the liquid that is injected and displaced within the formation. The mobility control is not dependent on the formation of a foam; although it is not adversely affected by the formation of a foam.
U.S. Pat. No. 4,856,589 describes a foam drive process in which the surfactant is injected as a dilute aqueous solution in which the surfactant is present at a concentration below its critical micelle concentration (CMC). It is stated that the method is particularly useful in a WAG operation, where multiple injections of dilute surfactant solution are alternated with injections of gas. In another mode, a conventional surfactant preslug, containing surfactant at a concentration above its CMC, is injected first. This preslug is followed by injection of a gas, then injection of a second, dilute surfactant solution containing surfactant at a concentration below its CMC, and then by injection of more gas. Injection of the gas and dilute surfactant solution may then be repeated.
The conventional injection procedures most commonly used in the limited field testing reported to date include adding surfactant to the water at a constant concentration in Water-Alternating-Gas (WAG) or Water-Simultaneous-Gas (WSG) injection to generate foam in situ, or injecting preformed foam. The preferred approach has been to coinject surfactant solution and gas or to use small alternating banks that simulate coinjection. Low surfactant concentrations, on the order of 0.1%, are commonly advocated. Even when surfactant retention is low, the amount of enhanced oil recovery obtained by using these conventional injection procedures may not be sufficient to justify the cost of the surfactant injected. Thus, there continues to be a significant need for improved injection procedures to effectively place the surfactant in the reservoir so as to minimize the amount of surfactant required.